Taught from an early age to generate or procure power from the lowest-cost resources, America’s utilities historically have scoffed at solar energy. In addition to its comparatively high cost and diminutive plant capacity, solar’s variable and non-dispatchable output poses technical issues that most utilities would prefer to avoid.

But solar technologies have been steadily scaling up in recent years, and becoming more cost effective. Plus, renewable portfolio standards (RPS) in 33 states are forcing utilities to make solar and other renewable energy sources a substantial part of their generation mix. A 2010 market study by consulting firm IHS Inc. spells it out: cumulative renewables demand across all states with binding RPS policies will grow from an expected 137 TWh (terawatt-hours) in 2010 to 479 TWh by 2025, an increase of approximately 250 percent.

Facing the need to comply with state mandates, utilities are increasingly moving toward development and ownership of renewable assets—including solar.

“Of the installed PV systems over 10 MW in the U.S., almost all have utilities or utility affiliates as large equity investors,” says Jay Paidipati, an associate director at Navigant Consulting. “Some of this is due to current and anticipated growth in compliance demand, but these projects can also provide good returns. Tax equity investors generally can command between 9 and 13 percent returns and [long-term] project equity investors typically command between 10 and 19 percent, depending on what stage of development they invest in.”

With photovoltaic (PV) panel costs declining, technology developers introducing new concentrated solar power (CSP) designs, and the federal government offering development grants—as well as construction loan guarantees, accelerated depreciation and tax credits that were previously off limits—the outlook for solar investments is starting to look downright bullish.

“We view solar as a real growth story,” says Tom Doyle, president of NRG Solar. The company owns and operates a 21 MW PV facility in Blythe, Calif., and is looking to invest more than $1 billion in two other projects—a 290 MW PV plant in Arizona and a 390 MW CSP plant in California. “We see significant growth in this space, which is why we control roughly 2 GW of proposals. Yes, there’s also wind power, but we believe that going forward it won’t grow like solar.”

Solar vs. Wind

Solar capacity in the U.S. currently represents less than 1 percent of the country’s electrical generating capacity, and any substantial uptick in that share is years away. But solar is quickly becoming a very real utility-scale resource and an investment opportunity; no longer are utilities making token commitments to solar power just to satisfy regulators.

That’s because, depending on the location, a solar asset can be a more valuable grid resource than its biggest rival, wind power. A PV installation, for example, operates best at times of peak electrical demand. Plus, siting is much more flexible. PV arrays can be located close to load centers, and can be installed relatively quickly and in small increments, perhaps on a warehouse rooftop or adjacent to an existing substation.

These characteristics mean a nimble solar PV project can be easier to permit, finance and build than the typical wind farm, which, because it’s usually far from a load center, often requires new transmission infrastructure to deliver the output.

Similarly, compared to PV, a solar CSP plant—which uses mirrors to gather and concentrate the sun’s heat to generate superheated steam—also takes longer to finance, permit and build, and might require new transmission capacity as well. But a CSP plant can leverage its power block—the steam generator and turbine, which can represent 50 percent of a power plant’s cost—with a heat storage facility or even an adjacent gas turbine to deliver more firm, less variable power output. You can’t do that, CSP developers say, with a wind farm.

Further, the cost of solar power technology continues to decline. Depending on the location, PV can deliver power at 11 to 12 cents a kilowatt-hour, making it competitive with gas-fired peaking plants in some parts of the country. “Solar PV has become a lot cheaper in the last five years,” says Declan Flanagan, CEO of Chicago-based Lincoln Renewable Energy, a private developer. “It’s gone from $8 per Watt installed, to between $3 and $4. That’s a 50 percent cost reduction, and the trend is continuing.”

PV system prices will continue dropping for a number of reasons, according to Paidipati. “You’ve got the learning curve, meaning the more you build the better you become at doing so; greater economies of scale as the industry continues to grow; lower silicon prices; and increased module and system efficiencies.”

The per-kilowatt-hour price for CSP assets is a bit higher, but it’s in the ballpark. “The prices we’ve seen for PPAs in the southwestern U.S. have ranged from 11 to 12 cents a kilowatt-hour, to the high teens, depending on the plant’s location and configuration,” says IHS Analyst Thomas Maslin.

Tax Appetite

While interest in solar is definitely a utility-by-utility proposition, there are generally two investment models. First, some regulated utilities are adding solar assets to their generation portfolio, either by building facilities or acquiring them. Under the second model, independent developers like NRG Solar are investing in or building merchant solar plants and selling the output to load-serving utilities under long-term power purchase agreements (PPA).

At this point, utilities are investing mostly in relatively small PV projects ranging from 1 to 30 MW in size, while independent developers and utility affiliates are investing in larger utility-scale PV and CSP projects that will add potentially thousands of megawatts of capacity over the next 10 to 20 years.

“To meet its RPS targets sooner, a utility can install PV assets near existing substations, usually in the 10, 20 or 30 MW size. In that size range, you can finance and deploy the equipment faster,” Maslin says. “The federal government’s 30 percent tax credit wasn’t previously an option to IOUs and now it’s been extended to the end of 2016. So if the utility has the tax appetite, it might want to choose the advantages of owning, versus buying the power through a PPA.”

For a regulated utility, the decision to build or buy can be a balancing act because many are already in the midst of other capital intensive projects, like transmission and distribution upgrades, says Andy Redinger, managing director of the energy utility group at KeyBanc Capital Markets.

“The U.S. utility industry hasn’t had a construction cycle like this one since the 1970s. At the same time, the renewable path adds even more spending,” Redinger says. “You’ve got a slowing economy, state and local governments that are in difficulty, and taxes are going up. We’re talking about a lot of money, and utilities have to weigh the regulatory risk. Do they build a solar plant themselves or buy the power from someone else to meet their requirements? There are a lot of moving parts to this issue,” he says.

If a regulated utility can fold the asset into its rate base, Redinger adds, owning the facility is the most efficient option.

“If I’m a utility and I’m able to rate-base a gas plant or a solar plant, I’d probably choose the solar plant. A natural gas plant is clearly cheaper, but if the regulators agree and I have no solar assets, I’d say put it in the stack and use it to help make up the RPS,” he says.

In Arizona, electric utilities like Arizona Public Service (APS) must procure 15 percent of their energy from renewable resources by 2025. Though it has PPAs in place to buy some 700 MW of renewable power, including 370 MW of solar capacity, APS has begun developing its own solar projects too.

In 2010 it announced four utility-scale PV projects, including the 18-MW Gila Bend, 15-MW Luke, 17-MW Hyder and 20-MW Chino Valley projects. They’re all part of a program called “AZ Sun,” under which APS will invest about $500 million to develop 100 MW of utility-owned photovoltaic assets. With other projects still to come, the entire 100-MW portfolio is scheduled to be online by 2014.

“Compliance isn’t the only reason we’re investing in solar,” says Eran Mahrer, director of APS Renewables. “Arizona is a growth state and ours is a growth territory. A few years back the question for us became ‘How do we add renewable energy to meet our resource planning needs and fulfill our compliance objectives?’”

From a strategic standpoint, Mahrer says owning solar assets will help APS diversify its energy portfolio and lessen its long term risk.

“Only 100 MW of our 800 MW of utility-scale renewable capacity will be coming from APS-owned projects, so our objective now is to try to balance that out. Probably not 50/50, but we had to acknowledge that owning a little over 10 percent wasn’t completely managing that risk,” he says.

With the economic downturn, solar projects proposed by private developers that appeared promising several years ago have been terminated due to financing difficulties. APS reasoned that the changes in the tax law that now allow utilities to claim a 30 percent investment tax credit on renewable projects make utility ownership a better option. Further, the company also knew that with its balance sheet, it could greatly improve the chances that solar projects would be financed and developed.

“As a regulated utility we have the tax appetite, and we knew we could finance that type of solar asset efficiently,” Mahrer says. And owning a greater percentage of its renewable generation portfolio would also mitigate any potential risks associated with PPAs.

“For some utilities, the RPS mandate is still a key driver, but it’s no longer the only driver. The more progressive utilities are beginning to think about developing a portfolio of the future,” says Julia Hamm, president and CEO of the Solar Electric Power Association (SEPA). “While the price of a solar installation might be higher today, some utilities want to get their foot in the door and assess the business and technology issues now, rather than later.”

PV vs. Solar Thermal

Unregulated subsidiaries, like NRG Solar and San Diego-based Sempra Generation, on the other hand, are building larger-scale PV and CSP merchant projects specifically to serve regulated utilities looking to satisfy their RPS mandate. But like their regulated affiliates and peers, independent developers too are leveraging governmental supports, including DOE loan guarantees.

Sempra Generation, for example, is developing 1,000 MW of PV capacity in Arizona, Nevada and California. Its flagship project, the 48-MW Copper Mountain Solar facility in Boulder City, Nev., went commercial last December and is the largest operating PV plant in the country. The power from that plant, along with the company’s adjacent 10-MW PV El Dorado Solar plant, has been sold to Pacific Gas & Electric (PG&E) under separate 20-year contracts.

However, Sempra has much larger PV projects in development, including the 600-MW Mesquite project, located about 40 miles west of Phoenix, Ariz., and the 200-MW Rosamond PV project, located in the high desert about 90 miles north of Los Angeles.

“Renewable mandates are the driver. There is strong demand for renewable power in the Southwest region, and we see solar as a valuable part of that market,” says Sempra spokesman Scott Crider. “We chose PV over thermal technologies because, from a financing standpoint, it’s a more proven entity. There are also fewer moving parts, which we feel will reduce O&M costs, and no water is needed to operate the plant, which is an environmental benefit. Panel prices are declining as well. As more projects are built, the construction learning curve will also reduce costs.”

Construction on the first 150-MW phase of the Mesquite project is scheduled to begin later this year and should be completed by 2013. Sempra located the plant near the Hassayampa 500-kV switchyard, a major transmission hub that will enable it ship power to all southwestern U.S. markets. Power from the first phase will be sold to PG&E under a 20-year contract, pending approval from the California Public Utilities Commission.

Crider says changes to the federal tax laws are just as important to Sempra Generation as they are to IOUs. “The investment tax credit is absolutely a key component in developing our projects,” he says. “We’re investing in 30-year assets, so we need as much regulatory and political certainty as we can get. That obviously helps with the project financing as well.”

Federal support is playing an even greater role in new CSP projects. Though thermal technologies have been demonstrated on a relatively small scale, large plants featuring new CSP designs must rely on loan guarantees from the DOE to secure financial backing. One of the furthest along is Oakland-based BrightSource Energy’s 392-MW Ivanpah Solar plant, which employs a new solar tower technology.

Located in California’s Mojave Desert, Ivanpah will be the world’s largest solar plant when it begins operations in 2013. BrightSource will sell its output to both Southern California Edison and PG&E.

Unlike trough-based designs, the solar tower design employs flat mirrors on heliostats that follow and direct sunlight to the receiver tower. The company says a tower system has much lower heat losses because the heat-collecting pipes are concentrated in the receiver and not dispersed around the solar field.

The project received a conditional $1.37 billion DOE loan guarantee to help secure financing. NRG Solar will be investing up to $300 million over the next three years, and an NRG subsidiary will operate the plant once it goes commercial. In addition to the loan guarantee, NRG, BrightSource and other investors will also benefit from the federal government’s 30 percent tax grant and a five-year accelerated depreciation schedule.

“For this project we had to leverage the DOE loan guarantee, but we believe bank financing for the BrightSource technology will be available within the first year after commercial operation in 2013,” Doyle says. “What we liked about this project is thermal solar is more grid friendly than PV. We’re also sensitive to environmental concerns, and the design includes dry cooling, which addresses the water consumption issues associated with traditional CSP. We’re taking a long-term ownership position in this project, so sustainability is important to us.”

The facility is the first of several Ivanpah phases, and BrightSource expects the learning curve will ultimately reduce construction and O&M costs. The company also plans to move from the initial 130 MW per-tower design to an advanced, 250-MW supercritical steam receiver that will enhance overall efficiency and output. Molten salt storage can also be added if and when it’s needed.

“Compared to PV, CSP offers a higher capacity factor in terms of its relative output, so it delivers the power in a way utilities are more familiar with,” says Charles Ricker, senior vice president of business development at BrightSource. “As opposed to PV, we believe IOUs are more interested in owning and operating a plant like this, but they’re not early adopters. They’re more interested in letting others develop the plant, and then they acquire it after it’s operating. Or perhaps an unregulated subsidiary buys it.”

But in the final analysis, Ricker adds, every renewable resource has its place in the country’s electrical generation mix.

“PV is modular, which makes it much more nimble. The plants are smaller and you don’t have the same permitting and transmission interconnect requirements,” Ricker says. “We are producing a much larger plant, one that uses steam generating technology. The output is more firm and it has a greater load shifting or matching capability, especially if you add a storage system. And remember, when Ivanpah comes on line, it will produce as much electricity as all the PV assets in California combined.”